Conventionally, wells for oil and gas recovery are substantially vertical. A well bore is drilled from the surface to a position below a desired hydrocarbon containing formation, and then a casing, basically a steel pipe with a diameter just slightly smaller than the well bore, is placed inside the walls of the well bore and cemented into place. The walls of the casing that are located within the desired formation are perforated, and then the formation is fractured by pumping sand or a like proppant into the cased hole at high pressure. The pressurized proppant enters the formation through the perforations in the casing and breaks the formation with a series of fractures that expand as additional sand is pumped. After the formation is fractured, the resultant fractures act as permeable pathways allowing oil or gas to flow from the formation into the wellbore.
In contrast in a horizontal well, the well bore is drilled downward to the formation, and then turns to extend more or less horizontally through the formation. When drilling horizontal wells, coiled tubing is used where has the tubing as one continuous string coiled around a drum that reels pipe in or out to reach the desired depth, unlike conventional tubing where nine meter long lengths of pipe are screwed together as needed to position the tool at the bottom of the string at the desired location. Conventional tubing has the ability to rotate, such as to rotate a drill bit at the bottom of the tubing string, whereas coiled tubing cannot rotate, as it is anchored to the reel. The coiled tubing can bend to the required horizontal orientation to drill horizontally however, and typically the drilling bit is driven by a separate motor at the bottom end of the tubing driven by electric or hydraulic power. In a horizontal well, only the vertical portion of the well has a casing installed, and the horizontal well bore is left bare, comprising simply an open hole through the formation. Thus casing perforations are not required
Since rock formations, including hydrocarbon formations, are typically laid down in more or less horizontal layers, conventional vertical wells were fractured at one location only, where they passed through the formation. Horizontal wells have the significant advantage of extending for long distances through the formation. Thus production can generally speaking be increased by fracturing the formation at as many locations as possible along the length of the well bore that is located in the formation.
To attain additional fractures after the initial fracture, the initial fracture must be isolated to prevent the pressurized proppant from simply entering and enlarging the initial fracture. Thus the initial fracture is made at the farthest or deepest end of the horizontal well bore, and then that initial fracture is isolated by various mechanical, fluid, hydraulic, or cement barriers such that pressurized proppant can be pumped into the well bore to create a new fracture on the upper side of the initial fracture. This process is repeated along the horizontal length of the well bore until a number fractures have been made along the horizontal length of the well bore from the initial fracture at the deepest ends to a final fracture at the shallow end of the horizontal well bore.
The present systems for isolating prior fractures typically increase cost, pumping time, and complexity, and as well only a limited number of fractures can be placed.
In one system, used by Packers Plus of Calgary, Canada, a liner is placed in the horizontal well bore. The liner includes a series of 10-12 ball seats that progressively increase in size from the deepest to the shallowest end of the liner. Covered ports are defined in the walls of the liner at intervals between the ball seats, and the covers are designed to rupture at a progressively increasing pressures from the deepest to the shallowest end of the liner. Packers are positioned on the outside of the liner adjacent to each ball seat to seal off the liner to the open well bore to isolate each zone.
Thus in the Packers Plus system, the initial fracture is made by pushing a small diameter ball down the liner to seat in the farthest ball seat and seal the end of the liner. Proppant is then pumped into the liner and the pressure is increased until the covers of the ports between the farthest ball seat and the next adjacent ball seat rupture, allowing the proppant to form a fracture in the formation through the farthest ports. For example this initial rupture pressure might be 1000 pounds per square inch (psi), and the fracture made at these ports is limited to the fracture that can be made with a pressure of 1000 psi, since increasing the pressure above this may cause the next adjacent ports to rupture.
Once the initial fracture has been made, a slightly larger ball is pushed down the liner to seat in the next adjacent ball seat, sealing off and isolating the first fracture. Pressure is increased to that sufficient to rupture the covers on the next adjacent ports, for example 1200 psi, and the second fracture is made creating whatever fracture can be made with this slightly increased pressure of 1200 psi. This process is repeated until all the available ports have been ruptured and fractures made through them. When all fractures have been made, the intermediate balls are typically pushed up to the surface by the production flowing from the fractures, with the farthest ball remaining in place sealing the end of the liner. The liner with the ball seats is left in the well which complicates future well repair and re-working. This system is currently popular as it is effective at preventing communication between fractures.
A system used by Baker Hughes of Houston Tex. utilizes a permanent liner and ball seats similar to Packers Plus except it has sliding sleeves or trap doors that are opened when a fracture is required and then sealed and isolated with progressively larger balls. This system currently is capable of about 14 separate fractures. When the fracturing is complete the liner is again left in the hole.
Other systems are known that utilize a coiled tubing assembly. Once an initial fracture is completed, a gel (viscous silicone) plug is pumped down the well bore and allowed to harden to isolate the first fracture from later ones. After fracturing is completed, the gel plugs are drilled out leaving the wellbore open to future repairs and enhanced recovery. This system was initially popular but has been found to allow communication between fractures since the gel plugs do not seal well enough to resist the high pressures, often 3000 psi or more, of a fracturing operation.
It is also known to pump in cement to form the plugs instead of gel. The cement is allowed to harden, then a fracture is made, then a new plug, then fracturing, and so on. This system's main drawback is the time required for the cement to harden sufficiently. With a conventional fracturing operation costing thousands of dollars an hour, this is not economically feasible on any but the most productive wells.
It is also commonly required to isolate portions of a well bore for other well stimulation methods such as acidizing, swabbing, sandjetting, brazing, and the like. A system for isolating a portion of a well bore between upper and lower packers and providing fluid to the isolated portion is disclosed in U.S. Pat. No. 6,782,954 to Serafin et al. In the system a sliding sleeve is provided by a mandrel and housing between the upper and lower packers, and a bypass is provided through the sleeve from the well bore below the lower packer to the well bore above the upper packer. The upper and lower packers are activated and set by a first pressure and then a second increased pressure opens ports in the sliding sleeve in the isolated zone between the packers. The system includes springs, catches, fingers, and other moving parts which react to changes in pressure to move the housing relative to the mandrel to open and close the ports in the sliding sleeve.